D.97-06-060

Conclusions of Law

1. Transition costs are defined in §§ 367, 368, 375, and 376. For generation-related assets, transition costs are those that prove to be uneconomic in the new competitive framework.
2. For the most part, generation-related transition costs must be recovered by December 31, 2001. AB 1890 states that transition costs must be recovered as expeditiously as possible.
3. Transition costs related to power purchase agreements and QF contracts may be collected for the duration of the contract.
4. Employee-related transition costs may be collected through December 31, 2006.
5. The collection of transition costs may extend though March 31, 2002 to the extent collection of transition costs is impacted by CTC exemptions, the costs of funding renewables programs as defined in § 381(d), or BRPU settlement costs, with certain additional provisions, as defined in § 367.
6. Commission-approved electric restructuring implementation costs that are not collected from another source and which reduce the ability of the utilities to collect generation-related transition costs may be continue to be collected after December 31, 2001, as provided by § 376.
7. Pursuant to § 367, this Commission must make the final determinations of the uneconomic costs associated with generation-related assets. In addition, in order to determine the transition costs for generation-related assets, we must net the negative (above-market costs) and positive (below-market costs) transition costs of all utility-owned generation related assets. Valuation of these assets must occur by year-end 2001.
8. The utilities must amortize their uneconomic costs such that their recorded rate of return does not exceed the authorized rate of return on ratebase.
9. The utilities are at risk for generation-related transition costs that are not recovered by December 31, 2001.
10. We must implement the newly-added Public Utility Code sections according to the plain meaning of the statute, applying our knowledge of ratemaking practices, common sense, and our duty in carrying out the public interest.
11. Pursuant to D.96-12-077, as of January 1, 1997, rates are frozen at levels that were in place on June 10, 1996. This has the effect of allowing the utilities to accrue revenue prior to the beginning of the mandated transition period.
12. PG&E’s Rate Restructuring Settlement discussed the acceleration of the recovery of generation-related regulatory assets, but this must be evaluated in the context of the statute as a whole.
13. The utilities should accelerate the collection of those transition costs which earn a high rate of return and in a manner which provides the greatest tax benefits. At a minimum, the utilities should accelerate depreciation of these assets on a straight-line basis over a 48-month amortization period, including associated taxes and the reduced rate of return.
14. Regulatory assets which are subject to write-off because of FASB Statement No. 71 should be amortized ratably over a 48-month period. The specific assets to which this requirement applies will be determined after Phase 2 eligibility is determined.
15. In order to accommodate ongoing market valuations and accelerated recovery, PG&E, Edison, and SDG&E should recalibrate the remaining months of the recovery schedule to adjust the amortization schedule through the end of the transition period.
16. It is reasonable to require monthly and annual reports to track the recovery of transition costs, as well as to institute an annual transition cost proceeding, separate from the Revenue Adjustment Proceeding.
17. Employee-related transition costs have been protected by statute.
18. Pursuant to § 369, CTC does not apply to service taken under tariffs, contracts, or rate schedules that are on file, accepted, or approved by the FERC, unless otherwise authorized by the FERC.
19. While transition cost responsibility should be subject to as few exemptions as possible, the definition of departing load does not apply to Western’s customers who are increasing their allocation of federal preference load in a manner contemplated under the existing contract, as described herein. A customer outside of these specific federal preference power contractual agreements, or similar arrangements subject to § 369, who was taking PG&E service subject to CPUC jurisdiction prior to December 20, 1995, and then displaced that PG&E service with third-party generation, which is wheeled to that customer under a FERC-jurisdictional tariff, will be subject to CTC.
20. It is reasonable at this time to consider metering reliability according to the standards designated for utility meters in tariff Rule 17 for PG&E and Edison and Rule 18 for SDG&E.
21. Tariffs should be designed so that customers can understand the costs and implications of choosing various available service options.
22. As decisions are forthcoming in the direct access and unbundling proceedings, CTC tariffs may require modifications.
23. It is reasonable to accept the tariff modifications stipulated to at the Energy Division workshops.
24. The fire wall established by § 330(v) is established to address revenue shortfalls due to exemptions and to protect ratepayers from transition cost obligations being shifted as a result of these revenue shortfalls.
25. The memorandum accounts and methodology that have been proposed by PG&E and Edison in Exhibits 7 and 10, respectively, are acceptable for tracking these exemptions and should be implemented by PG&E, Edison, and SDG&E.
26. Section 374(a)(4) states that the provisions of subdivision (a) are no longer operative after March 31, 2002; therefore, irrigation district customers are no longer exempt from any transition costs which accrue in the period after March 31, 2002.
27. It is reasonable to adopt the same procedures for PG&E, Edison, and SDG&E for resolving dispute resolutions in departing load CTC statements that we found reasonable for PG&E in D.96-11-041.
28. It is reasonable to develop unique penalty procedures to ensure that departing load customers cannot bypass transition costs and increase the transition cost burden on full service and direct access customers.
29. PG&E, Edison, and SDG&E should treat CTC deposits according to Rule 7 of their existing tariffs; therefore, each utility is prohibited from applying a customer’s deposit toward missed CTC payments. Except to the extent that each utility’s Rule 7 allows the application of deposits to closing bills, CTC deposits may be applied to outstanding departing load transition costs at the end of the transition period.
30. The lump-sum payment used as a last-resort penalty for departing load customers is not anticompetitive.
31. It is reasonable to offer departing load customers the choice of making final lump-sum CTC payments to reflect the transition costs ensuing after March 31, 2002 or to allow these customers some form of continuing transition cost payments.
32. It is reasonable to augment the advice letter process for modifications to transition cost tariffs that occur in 1997 and 1998.
33. A 30-day protest period for transition cost advice letters is reasonable, in light of the many activities occurring in electric restructuring in 1997 and early 1998, and the complexity of the issues addressed.
34. This order should be effective today so that the ratemaking mechanism and tariff procedures may be implemented expeditiously.